1. Field of the Invention
The present invention relates generally to the exploitation of subterranean formations. More specifically, it relates to the exploitation of subterranean petroliferous formations using high density mixed-brine-based fluids such as drilling, drill-in, completion, hydraulic fracturing, work-over, packer, well treating, testing, spacer, or hole abandonment fluids. Yet more specifically, the field of this invention is fluid rheology, thickeners, viscosifiers, viscoelastic fluids, and the physical hydration of polymer additives into high density mixed-brine-based drilling, drill-in, completion, hydraulic fracturing, work-over, packer, well treating, testing, spacer, or hole abandonment fluids.
2. Discussion of Related Art
A wide variety of methods for exploiting subterranean petroliferous formations are known in the art, and the problems associated therewith are also well known. Brines are commonly used in drilling, drill-in, work-over, hydraulic fracturing, completion, packer, well treating, testing, spacer, or hole abandonment fluids because of their wide density range and their character of being free of suspended solids and essentially non-damaging to subterranean petroliferous formations. During the process of drilling and completing an oil well, it is often desirable to add polymer and possibly bridging agents, to viscosify the drilling or completion fluid and thereby to control fluid loss to the formation. As fluids are lost into the formation, these materials filter out and build up a filter cake at the rock face which limits further flow of fluids into the formation. Some fluids nevertheless invariably flow into the formation and can interact with formation matrix in such a way as to reduce the permeability of the formation to the subsequent in-flow or out-flow of fluid, especially oil, gas, condensate or other fluid targeted for withdraw and use. This reduction in the rock permeability is termed "formation damage".
Xanthan gum is commonly used as a viscosifying polymer in brine-based drilling fluids whereas the cheaper hydroxyethyl cellulose (HEC) is commonly used in a work-over fluid. Xanthan gum has superior tolerance to high pH and temperature and has superior thixotropic properties compared to other viscosifying polymers. The viscosifying polymer is usually added to the brine to thicken it so that it will have, for example, high carrying capacity for the cuttings produced while drilling and high viscosity for a work-over fluid to control fluid loss and minimize formation damage. Xanthan gum also has the ability to impart gel character to a brine so that it will have high carrying capacity for drill cuttings even when the drilling process is interrupted and the fluid becomes quiescent.
HEC is a typical viscosifier and fluid loss control agent which is known to cause relatively little damage to the formation. Guar gum and starch derivatives can also be used. However, HEC and other polymers are very slow to viscosify brines having densities above about 12.0 ppg and HEC does not viscosify formate brines. Heating can be required to reach a desired viscosity for some brines.
For many applications of brine-based drilling fluids, HEC lacks sufficient thermal stability and carrying capacity for the drill cuttings. In these cases, therefore, xanthan gum is typically used instead. While such agents as HEC and xanthan gum impart both viscosity and fluid loss control to the drilling, drill in, completion, hydraulic fracturing, work over, well treating, spacer, or hole abandonment fluids, starches are often added to augment the fluid loss properties. Standard brine based drilling fluid may also include a bridging agent, such as, for example, sized particles of calcium carbonate or sodium chloride. In addition, a representative brine based drilling fluid can also include, for example, corrosion inhibitors, lubricants, pH control additives, surfactants, solvents, and/or weighting agents.
Conventional techniques for viscosifying a brine are limited by the fact that so much of the water in the brine is devoted to solubilization of the salt that there is not enough water left over for the solubilization of the viscosifying agent. In effect, the viscosifying agent is "salted out". Additionally, mixed-salt brines are often limited by salt solubilities to relatively low densities. For example, when a dense brine based on NaBr is added to a dense brine based on Ca(NO.sub.3).sub.2, the precipitation of solid NaNO.sub.3 depletes the solution so much that the remaining brine is only of relatively moderate density. As another example, the same sort of interaction and precipitation occurs when a dense brine based on CaCl.sub.2 or CaBr.sub.2 is added to a dense brine based on K.sub.2 CO.sub.3. The present invention teaches a group of mixed salts which are preferred because they can be formulated up to relatively high densities and yet the availability of "free" water is sufficient to allow viscosifying polymers to hydrate acceptably up to relatively high concentrations. Hence, inventive mixed-salt compositions are capable of exhibiting relatively high viscosities.
Problems occur when attempting to use xanthan gum to viscosify high concentrations of divalent-cation-based brines where most of the water is associated with salt. These problems include the need for extended mixing times, high shear, and/or heat in order to viscosify the brine. Similar problems occur with other viscosifiers. These problems are relatively minor in the brine concentration range extending most of the way from fresh water to almost saturated brine, then suddenly the problems get much more serious when just a relatively small amount of extra salt is added to a near-saturated brine.
One example is viscosifying xanthan gum in brines having high concentrations of CaBr.sub.2, where most of the water is occupied by the salt. This system requires extended mixing times, high shear, and/or heat in order to viscosity the brine. (See Table 1A).
TABLE 1A __________________________________________________________________________ Base Brine Steps Needed wt. % % Density to Viscosify CaBr.sub.2 saturation (ppg) the Brine Uniformly @ 1-5 ppb __________________________________________________________________________ 0 to 47.9 0.0 to 83.5 8.3 to 13.5 Stirring xanthan gum into the brine at room temperature; no extra shear needed; no extra heating needed. 48.5 to 51.3 84.5 to 13.6 to 14.1 Stirring xanthan gum into the brine at room 89.4 temperature followed by moderate shearing or mild warming. 51.9 90.4 14.2 Stirring xanthan gum into the brine followed by extensive shearing at room temperature or mild shearing combined with moderate heating. 52.4 to 57.4 91.3 to 14.3 to 15.35 Stirring xanthan gum into the brine at room 100.0 temperature followed by extensive mixing and shearing while heating steadily until polymer hydrates sufficiently. __________________________________________________________________________
The data clearly show the need for extended mixing times, high shear, and/or heat in order to viscosify CaBr.sub.2 brines above about 85% saturation.
When 3 pounds per barrel (ppb) of xanthan gum is added to a 14.2 pounds per gallon (ppg) substantially pure CaBr.sub.2 solution, stirred vigorously for an hour at room temperature, 70.degree. F., and sheared for 10 minutes on a Silverson mixer Model L4RT at 4000 rpm, it does not viscosity by indication of a yield point (YP) of 0 measured on a variable speed rheometer. It was noticed that by stirring the solution energetically for one hour at 125.degree. F. the xanthan gum viscosified with a YP of 62 and a viscosity at the 3 rpm reading of 2700 cp as shown in Table 1B. Stirring shears the solution but not nearly the amount of shear the Silverson mixer can provide.
To determine the temperature at a specific shear needed to viscosify 14.2 ppg CaBr.sub.2 solutions, a Fann Model 50 study was performed to monitor the viscosity at shear and temperature with time. The solutions were slowly heated to 150.degree. F. at 0.5 degrees per minute and allowed to remain at that temperature until maximum viscosity was achieved. Two separate tests were performed at shear rates of 511 sec.sup.-1 (300 rpm) and 170 sec.sup.-1 (100 rpm). The temperatures at which 25% of maximum viscosity was obtained were found to be 122.degree. F. and 143.degree. F., respectively. FIG. 1 illustrates these results and shows that 2.5 additional hours are needed to viscosify the solution at 170 sec.sup.-1 (100 rpm) than at 511 sec.sup.-1 (300 rpm). Table 1B below also shows the maximum viscosity of this 14.2 ppg CaBr.sub.2 solution obtained by different methods. This indicates that heating and shearing equipment would be needed in order to fully viscosity this solution.
TABLE 1B __________________________________________________________________________ 14.2 ppg CaBr.sub.2 + 3 ppb of Xanthan Viscosity, cp Viscosity, cp Viscosity, cp Viscosity, cp RPM 70.degree. F. 70.degree. F. 70.degree. F. 70.degree. F. __________________________________________________________________________ 600 11 78 81 84 300 11 109 109 107 3 2700 2600 2400 PV 11 47 53 61 YP 0 62 56 46 n 0.32 0.33 0.33 K, cp 7000 6700 6100 Method Stirred 1 hour at Stirred energetically Fann Model 50 at Fann Model 50 at 70.degree. F., shear 10 for 1 hour at 125.degree. F. 170 sec.sup.-1 at 150.degree. F. 511 sec.sup.-1 at 150.degree. F. min/4000 rpm for 5 hrs. for 2 hrs. __________________________________________________________________________
It has been shown that biopolymers like xanthan gum show a transition temperature (T.sub.m) in brines of various densities. A transition temperature is the temperature at which the polymer undergoes an order-disorder conformation change. This conformation change is accompanied by a massive loss of viscosity and increase in the rate of hydrolytic degradation by two orders of magnitude. It has also been shown that CaBr.sub.2 solutions above 10.4 ppg have a T.sub.m of less than 80.degree. C. and that degradation occurs at higher densities. T.sub.m has been used as a guide for predicting thermal stability of the polymers in brine solutions.
A variety of well servicing fluids and associated systems have been proposed in the prior art. There has remained a need for improved systems having advantageous characteristics for viscosification and fluid loss control, dispersability and hydration. Accordingly, the present invention is directed toward enhancing the thermal stability, viscosity and gel structure of dense brine-based drilling, drill-in, completion, hydraulic fracturing, work-over, packer, well treating, testing, spacer, or hole abandonment fluids and toward increasing the thermal stability of the water-soluble or water-dispersable polymer used to viscosity and gel the brines.